Irreducible fluid saturation water

Permeability, which characterizes the ability of rocks to allow the movement of fluids contained in their pores, is one of the most important parameters describing the porous media. Normally, in order to measure the permeability, the sample must have a simple geometric shape (e.g. cylinder or cube) and certain dimensions. On the other hand, measurements of porosity, pore-size distribution, and specific surface area do not require special geometric dimensions. The correlations among permeability and other easier-to-measure parameters, therefore, have been studied theoretically and experimentally. In practice, the most often reported correlation is that between the permeability and porosity The coefficient of correlation for porosity-permeability relationship varies from sample to sample, with a better correlation if the porosity used in the calculation is measured when a core contains the irreducible fluid. Porosity does not reflect the number and width of fractures, the pore sizes and topological structure, whereas the specific surface area does. Thus, it appears advisable to relate permeability simultaneously to porosity, specific surface area, irreducible water/oil saturation, grain size/pore size/throat size distribution, tortuosity, etc. 

Reservoir parameters for the two sandstone members are summarized in Table 1. Reservoir rock properties and fluid saturations were developed from log and core measurements obtained in the seven wells drilled to complete pilot area development. The initial oil saturation of 75 per cent indicated by log analysis is substantiated by both capillary pressure and resaturation data which indicate interstitial water saturations near the irreducible level. Residual oil saturations developed for each reservoir represent averages obtained from floodout of over 100 samples taken from the Vernon field. 

Accurate interpretation of the formation properties (porosity, permeability and irreducible water saturation) requires reliable estimates of NMR fluid properties or the relationship between diffusivity and relaxation time. Estimation of oil viscosity and solution-gas content require their correlation with NMR measurable fluid properties. These include the hydrogen index, bulk fluid relaxation time and bulk fluid diffusivity [8]. 

If the NMR response is capable of estimating the pore size distribution, then it also has the potential to estimate the fraction of the pore space that is capable of being occupied by the hydrocarbon and the remaining fraction that will only be occupied by water. The Free Fluid Index (FFI) is an estimate of the amount of potential hydrocarbons in the rock when saturated to a given capillary pressure. It is expressed as a fraction of the rock bulk volume. The Bulk Volume Irreducible (BVI) is the fraction of the rock bulk volume that will be occupied by water at the same capillary pressure. The fraction of the rock pore volume that will only be occupied by water is called the irreducible water saturation (Siwr = BVI/cj>). The amount of water that is irreducible is a function of the driving force to displace water, i.e., the capillary pressure. Usually the specified driving force is an air-water capillary pressure of 0.69 MPa (100 psi). 

Interpretation for irreducible water saturation assumes that the rock is water-wet or mixed-wet (water-wet during drainage but the pore surfaces contacted by oil becomes oil-wet upon imbibition). If a porous medium is water-wet and a nonwetting fluid displaces the water (drainage), then the non-wetting fluid will first occupy the larger pores and will enter the smaller pores only as the capillary pressure is increased. This process is similar to the accumulation of oil or gas in the pore space of a reservoir. Thus it is of interest to estimate the irreducible water saturation that is retained by capillarity after the hydrocarbon accumulates in an oil or gas reservoir. The FFI is an estimate of the amount of potential hydrocarbon in... 

Interpretation of NMR well logs is usually made with the assumption that the formation is water-wet such that water occupies the smaller pores and oil relaxes as the bulk fluid. Examination of crude oil, brine, rock systems show that a mixed-wet condition is more common than a water-wet condition, but the NMR interpretation may not be adversely affected [47]. Surfactants used in oil-based drilling fluids have a significant effect on wettability and the NMR response can be correlated with the Amott-Harvey wettability index [46]. These surfactants can have an effect on the estimation of the irreducible water saturation unless compensated by adjusting the T2 cut-off [48]. 

NMR has proven to be a valuable tool for formation evaluation by well logging, downhole fluid analysis and laboratory rock characterization. It gives a direct measure of porosity as the response is only from the fluids in the pore space of the rock. The relaxation time distribution correlates with the pore size distribution. This correlation makes it possible to estimate permeability and irreducible water saturation. When more than one fluid is present in the rock, the fluids can be identified based on the difference in the fluid diffusivity in addition to relaxation times. Interpretation of NMR responses has been greatly advanced with the ability to display two distributions simultaneously. 

Wettability. Wettability of the porous medium controls the flow, location, and distribution of fluids inside a reservoir (7, 28). It directly affects capillary pressure, relative permeability, secondary and tertiary recovery performances, irreducible water saturations, residual oil saturations, and other properties. 

Fig. 4 summarizes relative permeability measurements derived from displacement studies conducted on one lower and two upper reservoir rock samples. Reservoir oil and synthesized formation water were the displaced and displacing fluids. Relative permeabilities of oil and water were calculated for the complete saturation range from floodout history. Results exhibit relatively good agreement with end-point measurements of water permeability and residual oil saturation. The lower sandstone sample is not considered representative of that reservoir in view of the anomalously low residual oil saturation. Relative permeability to water is expressed as a fraction of relative permeability to oil at irreducible water saturation. 

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